Contaminant removal from hydrocarbon streams with ionic liquids

ABSTRACT

A process for removing sulfur and nitrogen contaminants from a hydrocarbon stream using a Brønsted acid or an ionic liquid and a Brønsted acid is described. The process includes contacting the hydrocarbon stream comprising the contaminant with a Brønsted acid or a hydrocarbon-immiscible ionic liquid and the Brønsted acid to produce a mixture comprising the hydrocarbon and the Brønsted acid comprising at least a portion of the removed contaminant or a hydrocarbon-immiscible ionic liquid comprising at least a portion of the removed contaminant; and separating the mixture to produce a hydrocarbon effluent having a reduced level of the contaminant and a Brønsted acid effluent comprising the Brønsted acid comprising at least the portion of the removed contaminant or a hydrocarbon-immiscible ionic liquid effluent comprising the hydrocarbon-immiscible ionic liquid comprising at least the portion of the removed contaminant.

BACKGROUND OF THE INVENTION

Various hydrocarbon streams, such as vacuum gas oil (VGO), light cycleoil (LCO), and naphtha, may be converted into higher value hydrocarbonfractions such as diesel fuel, jet fuel, naphtha, gasoline, and otherlower boiling fractions in refining processes such as hydrocracking andfluid catalytic cracking (FCC). However, hydrocarbon feed streams forthese materials often have high amounts of nitrogen which are moredifficult to convert. For example, the degree of conversion, productyields, catalyst deactivation, and/or ability to meet product qualityspecifications may be adversely affected by the nitrogen content of thefeed stream. It is known to reduce the nitrogen content of thesehydrocarbon feed streams by catalytic hydrogenation reactions such as ina hydrotreating process unit. However, hydrogenation processes requirerelatively high pressures and temperatures.

Various processes using ionic liquids to remove sulfur and nitrogencompounds from hydrocarbon fractions are also known. U.S. Pat. No.7,001,504 discloses a process for the removal of organosulfur compoundsfrom hydrocarbon materials which includes contacting an ionic liquidwith a hydrocarbon material to extract sulfur containing compounds intothe ionic liquid. U.S. Pat. No. 7,553,406 discloses a process forremoving polarizable impurities from hydrocarbons and mixtures ofhydrocarbons using ionic liquids as an extraction medium. U.S. Pat. No.7,553,406 also discloses that different ionic liquids show differentextractive properties for different polarizable compounds.

There remains a need in the art for improved processes that enable theremoval of contaminants from hydrocarbon streams.

SUMMARY OF THE INVENTION

One aspect of the invention is a process for removing a contaminantcomprising at least one of sulfur and nitrogen from a hydrocarbonstream. In one embodiment, the process includes contacting thehydrocarbon stream comprising the contaminant with a Brønsted acid or ahydrocarbon-immiscible ionic liquid and a Brønsted acid under contactingconditions so that the Brønsted acid, or the hydrocarbon-immiscibleionic liquid and the Brønsted acid are in a liquid state to produce amixture comprising the hydrocarbon and the Brønsted acid comprising atleast a portion of the removed contaminant or a hydrocarbon-immiscibleionic liquid comprising at least a portion of the removed contaminant.The mixture is separated to produce a hydrocarbon effluent having areduced level of the contaminant and a Brønsted acid effluent comprisingthe Brønsted acid comprising at least the portion of the removedcontaminant or a hydrocarbon-immiscible ionic liquid effluent comprisingthe hydrocarbon-immiscible ionic liquid comprising at least the portionof the removed contaminant.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a simplified flow scheme illustrating various embodiments ofthe invention.

FIGS. 2A and 2B are simplified flow schemes illustrating differentembodiments of an extraction zone of the invention.

DETAILED DESCRIPTION OF THE INVENTION

In general, the invention may be used to remove sulfur and nitrogencontaminants from a hydrocarbon stream using a Brønsted acid or an ionicliquid and a Brønsted acid. The Brønsted acid can remove sulfur andnitrogen contaminants. The combination of the ionic liquid and theBrønsted acid removes more of the sulfur and nitrogen contaminants thanthe ionic liquid alone.

The hydrocarbon stream typically has a boiling point in the range ofabout 30° C. to about 525° C. Examples of hydrocarbon streams include,but are not limited to, at least one of vacuum gas oil streams, lightcycle oil streams, naphtha streams, coker gas oil streams, kerosenestreams, streams made from biorenewable sources, fracking condensatestreams, streams from hydrocracking zones, streams from hydrotreatingzones, and streams from fluid catalytic cracking zones.

The sulfur and nitrogen contaminants are one or more species found inthe hydrocarbon material that is detrimental to further processing. Thetotal sulfur content may range from 0.1 to 7 wt %, and the nitrogencontent may be from about 40 ppm to 30,000 ppm.

The ionic liquid and the Brønsted acid can remove one or more of thesulfur and nitrogen contaminants in the hydrocarbon feed. Thehydrocarbon feed will usually comprise a plurality of nitrogen compoundsof different types in various amounts. Thus, at least a portion of atleast one type of nitrogen compound may be removed from the hydrocarbonfeed. The same or different amounts of each type of nitrogen compoundcan be removed, and some types of nitrogen compounds may not be removed.In an embodiment, up to about 99 wt % of the nitrogen can be removed.The nitrogen content of the hydrocarbon feed is typically reduced by atleast about 10 wt %, at least about 20 wt %, or at least about 30 wt %,or at least about 40 wt %, at least about 50 wt %, or at least about 60wt %, or at least about 70 wt %, or at least about 80 wt %, or at leastabout 90 wt %, or at least about 95 wt %.

The hydrocarbon feed will typically also comprise a plurality of sulfurcompounds of different types in various amounts. Thus, at least aportion of at least one type of sulfur compound may be removed from thehydrocarbon feed. The same or different amounts of each type of sulfurcompound may be removed, and some types of sulfur compounds may not beremoved. In an embodiment, up to about 30 wt % of the sulfur can beremoved. Typically, the sulfur content of the hydrocarbon feed isreduced by at least about 1 wt %, or at least about 2 wt %, or at least3 wt %, or at least 5 wt %, or at least 10 wt %, or at least 15 wt %, orat least 20 wt %, or at least 25 wt %.

Consistent with common terms of art, the ionic liquid introduced to thefeed extraction zone may be referred to as a “lean ionic liquid”generally meaning a hydrocarbon feed-immiscible ionic liquid that is notsaturated with one or more extracted contaminants. Lean ionic liquid mayinclude one or both of fresh and regenerated ionic liquid and issuitable for accepting or extracting contaminants from the hydrocarbonfeed. Likewise, the ionic liquid effluent may be referred to as “richionic liquid”, which generally means a hydrocarbon feed-immiscible ionicliquid effluent produced by a contaminant removal step or process orotherwise including a greater amount of extracted contaminants than theamount of extracted contaminants included in the lean ionic liquid. Arich ionic liquid may require regeneration or dilution, e.g. with freshionic liquid, before recycling the rich ionic liquid to the same oranother contaminant removal step of the process.

Generally, ionic liquids are non-aqueous, organic salts composed of ionswhere the positive ion is charge balanced with a negative ion. Thesematerials have low melting points, often below 100° C., undetectablevapor pressure, and good chemical and thermal stability. The cationiccharge of the salt is localized over hetero atoms, such as nitrogen,phosphorous, sulfur, arsenic, boron, antimony, and aluminum, and theanions may be any inorganic, organic, or organometallic species.

Ionic liquids suitable for use in the instant invention are hydrocarbonfeed-immiscible ionic liquids. As used herein the term “hydrocarbonfeed-immiscible ionic liquid” means the ionic liquid is capable offorming a separate phase from hydrocarbon feed under the operatingconditions of the process. Ionic liquids that are miscible withhydrocarbon feed at the process conditions will be completely solublewith the hydrocarbon feed; therefore, no phase separation will befeasible. Thus, hydrocarbon feed-immiscible ionic liquids may beinsoluble with or partially soluble with the hydrocarbon feed under theoperating conditions. An ionic liquid capable of forming a separatephase from the hydrocarbon feed under the operating conditions isconsidered to be hydrocarbon feed-immiscible. Ionic liquids according tothe invention may be insoluble, partially soluble, or completely soluble(miscible) with water.

In an embodiment, the hydrocarbon feed-immiscible ionic liquid comprisesat least one of an imidazolium ionic liquid, a pyridinium ionic liquid,a phosphonium ionic liquid, a lactamium ionic liquid, an ammonium ionicliquid, and a pyrrolidinium ionic liquid. In another embodiment, thehydrocarbon feed-immiscible ionic liquid consists essentially ofimidazolium ionic liquids, pyridinium ionic liquids, phosphonium ionicliquids, lactamium ionic liquids, ammonium ionic liquids, pyrrolidiniumionic liquids, and combinations thereof. In still another embodiment,the hydrocarbon feed-immiscible ionic liquid is selected from the groupconsisting of imidazolium ionic liquids, pyridinium ionic liquids,phosphonium ionic liquids, lactamium ionic liquids, ammonium ionicliquids, pyrrolidinium ionic liquids, and combinations thereof.Imidazolium, pyridinium, lactamium, ammonium, and pyrrolidinium ionicliquids have a cation comprising at least one nitrogen atom. Phosphoniumionic liquids have a cation comprising at least one phosphorous atom.

The ionic liquid comprises at least one ionic liquid from the followingionic liquids: tetraalkylphosphonium dialkylphosphates,tetraalkylphosphonium dialkyl phosphinates, tetraalkylphosphoniumphosphates, tetraalkylphosphonium tosylates, tetraalkylphosphoniumsulfates, tetraalkylphosphonium sulfonates, tetraalkylphosphoniumcarbonates, tetraalkylphosphonium metalates, oxometalates,tetraalkylphosphonium mixed metalates, tetraalkylphosphoniumpolyoxometalates, tetraalkylphosphonium halides,trihexyl(tetradecyl)phosphonium halides imidazolium imides, imidazoliumhexafluorophosphates, imidazolium thiocyanates, imidazoliumdicyanamides, imidazolium acetates, imidazolium bromides, imidazoliumchlorides, imidazolium tetrafluoroborates, pyridiniumtetrafluoroborates, pyridinium imides, pyridinium hexafluorophosphates,pyridinium bromides, pyridinium trifluoromethanesulfonates,pyrrolidinium imides, and pyrrolidinium trifluoromethanesulfonates, andpyrrolidinium sulfonium imides.

In an embodiment, the hydrocarbon feed-immiscible ionic liquid comprisesat least one of 1-ethyl-3-methylimidazolium dicyanamide,1-ethyl-3-methylimidazolium ethyl sulfate, 1-butyl-3-methylimidazoliumhydrogen sulfate, 1-ethyl-3-methylimidazolium chloride,1-butyl-3-methylimidazolium chloride, 1-butyl-3-methylimidazoliumtrifluoromethanesulfonate, 1-ethyl-3-methylimidazoliumbis(trifluoromethylsulfonyl)imide, 1-butyl-3-methylimidazoliumhexafluorophosphate, 1-butyl-3-methylimidazolium tetrafluoroborate,methylimidazolium trifluoroacetate, 1-butyl-3-methylimidazolium bromide,1-ethyl-3-methylimidazolium trifluoroacetate, 1-methylimidazoliumhydrogen sulfate, 1-butyl-4-methylpyridinium chloride,N-butyl-3-methylpyridinium methylsulfate, 1-butyl-4-methypyridiniumhexafluorophosphate, pyridinium p-toluene sulfonate, 1-butylpyridiniumchloride, tetraethyl-ammonium acetate, trihexyl(tetradecyl)phosphoniumchloride, trihexyl(tetradecyl)phosphonium bromide,tributyl(methyl)phosphonium bromide, tributyl(methyl)phosphoniumchloride, tributyl(hexyl)phosphonium bromide, tributyl(hexyl)phosphoniumchloride, tributyl(octyl)phosphonium bromide, tributyl(octyl)phosphoniumchloride, tributyl(decyl)phosphonium bromide, tributyl(decyl)phosphoniumchloride, tetrabutylphosphonium bromide, tetrabutylphosphonium chloride,triisobutyl(methyl)phosphonium tosylate, tributyl(ethyl)phosphoniumdiethylphosphate, tetrabutylphosphonium methanesulfonate, pyridiniump-toluene sulfonate, tributyl(methyl)phosphonium methylsulfate.

Lactamium ionic liquids include, but are not limited to, those describedin U.S. Pat. No. 8,709,236, U.S. application Ser. No. 14/271,308,entitled Synthesis of Lactam Based Ionic Liquids, filed May 6, 2014, andU.S. application Ser. No. 14/271,319, entitled Synthesis ofN-Derivatized Lactam Based Ionic Liquids, filed May 6, 2014, which areincorporated by reference.

Brønsted acids suitable for use include, but are not limited to,sulfonic acid, derivatives of sulfonic acid, sulfuric acid, phosphoricacid, derivatives of phosphoric acid, phosphonic acids, hydrochloricacid, hydrobromic acid, nitric acid, sulfurous acid, carboxylic acidshaving from 1 to 8 carbons, and combinations thereof. By derivatives ofsulfonic acid and phosphoric acid, we mean ordinary chemical reactionsthat change one compound to another while keeping the base structureunaltered. Examples of derivatives of sulfonic acid include, but are notlimited to p-toluenesulfonic acid, methanesulfonic acid, benzenesulfonicacid, propane-1-sulfonic acid, hexadecane-1-sulfonic acid, andbutane-2-sulfonic acid. Examples of derivatives of phosphoric acidinclude, but are not limited to tris(2-ethylhexyl)phosphate,2-ethylhexylphosphate, dibutyl hydrogen phosphate, tributyl hydrogenphosphate, and bis(2-ethylhexyl) hydrogen phosphate. Examples ofderivatives of phosphonic acid include, but are not limited to,amino-tris-methylenephosphonic acid (ATMP) and1-hydroxyethylidene-1,1-diphosphonic acid (HEDP).

The ratio of the Brønsted acid to the hydrocarbon-immiscible ionicliquid is in a range of about to about 0.01:1 to about 0.5:1, or about0.1:1 to about 0.3:1.

In an embodiment, the invention is a process for removing sulfur andnitrogen contaminants from a hydrocarbon feed stream comprising acontacting step and a separating step. In the contacting step, ahydrocarbon feed stream comprising a contaminant, ahydrocarbon-immiscible ionic liquid, and a Brønsted acid are contactedor mixed. The contacting may facilitate transfer or extraction of theone or more contaminants from the hydrocarbon feed stream to the ionicliquid. Although an ionic liquid that is partially soluble in thehydrocarbon may facilitate transfer of the contaminant from thehydrocarbon to the ionic liquid, partial solubility is not required.Insoluble hydrocarbon/ionic liquid mixtures may have sufficientinterfacial surface area between the hydrocarbon and ionic liquid to beuseful. In the separation step, the mixture of hydrocarbon and ionicliquid settles or forms two phases, a hydrocarbon phase and an ionicliquid phase, which are separated to produce a hydrocarbon-immiscibleionic liquid effluent and a hydrocarbon effluent.

The process may be conducted in various equipment which is well known inthe art and is suitable for batch or continuous operation. For example,in a small scale form of the invention, the hydrocarbon, thehydrocarbon-immiscible ionic liquid, and the Brønsted acid may be mixedin a beaker, flask, or other vessel, e.g., by stirring, shaking, use ofa mixer, or a magnetic stirrer. The mixing or agitation is stopped andthe mixture forms a hydrocarbon phase and an ionic liquid phase whichcan be separated, for example, by decanting, centrifugation, or use of apipette to produce a hydrocarbon effluent having a lower contaminantcontent relative to the incoming hydrocarbon. The process also producesa hydrocarbon-immiscible ionic liquid effluent comprising the one ormore contaminants.

The contacting and separating steps may be repeated, for example, whenthe contaminant content of the hydrocarbon effluent is to be reducedfurther to obtain a desired contaminant level in the ultimatehydrocarbon product stream from the process. Each set, group, or pair ofcontacting and separating steps may be referred to as a contaminantremoval step. Thus, the invention encompasses single and multiplecontaminant removal steps. A contaminant removal zone may be used toperform a contaminant removal step. As used herein, the term “zone” canrefer to one or more equipment items and/or one or more sub-zones.Equipment items may include, for example, one or more vessels, heaters,separators, exchangers, conduits, pumps, compressors, and controllers.Additionally, an equipment item can further include one or more zones orsub-zones. The contaminant removal process or step may be conducted in asimilar manner and with similar equipment as is used to conduct otherliquid-liquid wash and extraction operations. Suitable equipmentincludes, for example, columns with: trays, packing, rotating discs orplates, and static mixers. Pulse columns and mixing/settling tanks mayalso be used.

FIG. 1 is a flow scheme illustrating various embodiments of theinvention and some of the optional and/or alternate steps and apparatusencompassed by the invention. Hydrocarbon stream 2,hydrocarbon-immiscible ionic liquid stream 4, and Brønsted acid stream 5are introduced to and contacted and separated in contaminant removalzone 100 to produce hydrocarbon-immiscible ionic liquid effluent stream8 and hydrocarbon effluent stream 6 as described above. The ionic liquidstream 4 may be comprised of fresh ionic liquid stream 3 and/or one ormore ionic liquid streams which are recycled in the process as describedbelow. In an embodiment, a portion or all of hydrocarbon effluent stream6 is passed via conduit 10 to a hydrocarbon conversion zone 800.Hydrocarbon conversion zone 800 may, for example, comprise at least oneof a fluid catalytic cracking and a hydrocracking process, which arewell known in the art.

The contacting takes place under conditions such that the Brønsted acidor the Brønsted acid and ionic liquid are in the liquid state.

The contact step can take place at a temperature in the range of about20° C. to the decomposition temperature of the ionic liquid, or about20° C. to about 150° C., or about 20° C. to about 120° C., or about 20°C. to about 80° C.

The pressure is typically in the range of about 100 kPa to about 3 MPa.

The contacting time is sufficient to obtain good contact between theionic liquid, the Brønsted acid, and the hydrocarbon feed. Thecontacting time is typically in the range of about 1 min to about 1 hr,or about 5 min to about 30 min.

An optional hydrocarbon washing step may be used, for example, torecover ionic liquid that is entrained or otherwise remains in thehydrocarbon effluent stream by using water to wash or extract the ionicliquid from the hydrocarbon effluent. In this embodiment, a portion orall of hydrocarbon effluent stream 6 (as feed) and a water stream 12 (assolvent) are introduced to hydrocarbon washing zone 400. The hydrocarboneffluent and water streams introduced to hydrocarbon washing zone 400are mixed and separated to produce a washed hydrocarbon stream 14 and aspent water stream 16, which comprises the ionic liquid. The hydrocarbonwashing step may be conducted in a similar manner and with similarequipment as used to conduct other liquid-liquid wash and extractionoperations as discussed above. Various hydrocarbon washing stepequipment and conditions such as temperature, pressure, times, andsolvent to feed ratio may be the same as or different from thecontaminant removal zone equipment and conditions. In general, thehydrocarbon washing step conditions will fall within the same ranges asgiven for the contaminant removal step conditions. A portion or all ofthe washed hydrocarbon stream 14 may be passed to hydrocarbon conversionzone 800.

A similar arrangement would be used for the Brønsted acid alone. TheBrønsted acid could be removed from the hydrocarbon by dilution withwater or water washing.

An optional ionic liquid regeneration step may be used, for example, toregenerate the ionic liquid by removing the contaminant from the ionicliquid, i.e. reducing the contaminant content of the rich ionic liquid.In an embodiment, a portion or all of hydrocarbon-immiscible ionicliquid effluent stream 8 (as feed) comprising the contaminant and aregeneration solvent stream 18 are introduced to ionic liquidregeneration zone 500. The hydrocarbon-immiscible ionic liquid effluentstream 8 and regeneration solvent stream 18 are mixed and separated toproduce an extract stream 20 comprising the contaminant, and aregenerated ionic liquid stream 22. The ionic liquid regeneration stepmay be conducted in a similar manner and with similar equipment as usedto conduct other liquid-liquid wash and extraction operations. Variousionic liquid regeneration step conditions such as temperature, pressure,times, and solvent to feed may be the same as or different from thecontaminant removal conditions. In general, the ionic liquidregeneration step conditions will fall within the same ranges as givenfor the contaminant removal step conditions.

In an embodiment, the regeneration solvent stream 18 comprises ahydrocarbon fraction lighter than the hydrocarbon and which isimmiscible with the ionic liquid. The lighter hydrocarbon fraction mayconsist of a single hydrocarbon compound or may comprise a mixture ofhydrocarbons. In an embodiment, the lighter hydrocarbon fractioncomprises at least one of a naphtha, gasoline, diesel, light cycle oil(LCO), and light coker gas oil (LCGO) hydrocarbon fraction. The lighterhydrocarbon fraction may comprise straight run fractions and/or productsfrom conversion processes such as hydrocracking, hydrotreating, fluidcatalytic cracking (FCC), reforming, coking, and visbreaking. In thisembodiment, extract stream 20 comprises the lighter hydrocarbonregeneration solvent and the contaminant. Other suitable regenerationsolvents include, but are not limited to, alcohols, aldehydes, ketones,ether, and combinations thereof. In these embodiments, extract stream 20comprises the alcohol, aldehyde, ketone, or ether regeneration solventand the contaminant. In another embodiment, the regeneration solventstream 18 comprises water, and the ionic liquid regeneration stepproduces extract stream 20 comprising the contaminant and regeneratedhydrocarbon-immiscible ionic liquid 22 comprising water and the ionicliquid. In an embodiment wherein regeneration solvent stream 18comprises water, a portion or all of spent water stream 16 may provide aportion or all of regeneration solvent stream 18. Regardless of whichregeneration solvent is used, a portion or all of regeneratedhydrocarbon-immiscible ionic liquid stream 22 may be recycled to thecontaminant removal step via a conduit not shown consistent with otheroperating conditions of the process. For example, a constraint on thewater content of the hydrocarbon-immiscible ionic liquid stream 4 or theionic liquid/hydrocarbon mixture in contaminant removal zone 100 may bemet by controlling the proportion and water content of fresh andrecycled ionic liquid streams.

Optional ionic liquid drying step is illustrated by drying zone 600. Theionic liquid drying step may be employed to reduce the water content ofone or more of the streams comprising ionic liquid to control the watercontent of the contaminant removal step as described above. In theembodiment of FIG. 1, a portion or all of regeneratedhydrocarbon-immiscible ionic liquid stream 22 is introduced to dryingzone 600. Although not shown, other streams comprising ionic liquid suchas the fresh ionic liquid stream 3, hydrocarbon-immiscible ionic liquideffluent stream 8, and spent water stream 16, may also be dried in anycombination in drying zone 600. To dry the ionic liquid stream orstreams, water may be removed by one or more various well known methodsincluding distillation, flash distillation, and using a dry inert gas tostrip water. Generally, the drying temperature may range from about 100°C. to less than the decomposition temperature of the ionic liquid,usually less than about 300° C. The pressure may range from about 35kPa(g) to about 250 kPa(g). The drying step produces a driedhydrocarbon-immiscible ionic liquid stream 24 and a drying zone watereffluent stream 26. Although not illustrated, a portion or all of driedhydrocarbon-immiscible ionic liquid stream 24 may be recycled or passedto provide all or a portion of the hydrocarbon-immiscible ionic liquidintroduced to contaminant removal zone 100. In the case of recycle tothe contaminant removal zone, additional Brønsted acid can be added asneeded. A portion or all of drying zone water effluent stream 26 may berecycled or passed to provide all or a portion of the water introducedinto hydrocarbon washing zone 400 and/or ionic liquid regeneration zone500.

FIG. 2A illustrates an embodiment of the invention which may bepracticed in contaminant removal or extraction zone 100 that comprises amulti-stage, counter-current extraction column 107 wherein hydrocarbonand hydrocarbon-immiscible ionic liquid are contacted and separated. Thehydrocarbon feed stream 2 enters extraction column 107 through feedinlet 102, lean ionic liquid stream 4 enters extraction column 107through ionic liquid inlet 104, and Brønsted acid stream 5 entersextraction column 107 through Brønsted acid inlet 105. Alternatively,the lean ionic liquid stream 4 and Brønsted acid stream 5 could be mixedbefore being introduced into the extraction column 107. In the Figures,reference numerals of the streams and the lines or conduits in whichthey flow are the same. Hydrocarbon feed inlet 102 is located belowionic liquid inlet 104 and Brønsted acid inlet 105. The hydrocarboneffluent passes through hydrocarbon effluent outlet 112 in an upperportion of extraction column 107 to hydrocarbon effluent conduit 6. Thehydrocarbon-immiscible ionic liquid effluent including the contaminantsremoved from the hydrocarbon feed passes through ionic liquid effluentoutlet 114 in a lower portion of extraction column 107 to ionic liquideffluent conduit 8.

FIG. 2B illustrates another embodiment of contaminant removal washingzone 100 that comprises a contacting zone 200 and a separation zone 300.In this embodiment, lean ionic liquid stream 4, Brønsted acid stream 5,and hydrocarbon feed stream 2 are introduced into the contacting zone200 and mixed by introducing Brønsted acid stream 5 and hydrocarbon feedstream 2 into the flowing lean ionic liquid stream 4 and passing thecombined streams through static in-line mixer 155. Static in-line mixersare well known in the art and may include a conduit with fixed internalssuch as baffles, fins, and channels that mix the fluid as it flowsthrough the conduit. In other embodiments, not illustrated, lean ionicliquid stream 4 and Brønsted acid stream 5 may be introduced intohydrocarbon feed stream 2. In another embodiment, lean ionic liquidstream 4, Brønsted acid stream 5, and hydrocarbon feed stream 2 areseparately introduced into the static in-line mixer 155. In otherembodiments, the streams may be mixed by any method well known in theart, including stirred tank and blending operations. The mixturecomprising hydrocarbon, ionic liquid, and Brønsted acid is transferredto separation zone 300 via transfer conduit 7. Separation zone 300comprises separation vessel 165 wherein the two phases are allowed toseparate into a rich ionic liquid phase which is withdrawn from a lowerportion of separation vessel 165 via ionic liquid effluent conduit 8 anda hydrocarbon phase which is withdrawn from an upper portion ofseparation vessel 165 via hydrocarbon effluent conduit 6. Separationvessel 165 may comprise a boot, not illustrated, from which rich ionicliquid is withdrawn via conduit 8.

Separation vessel 165 may contain a solid media 175 and/or othercoalescing devices which facilitate the phase separation. In otherembodiments, the separation zone 300 may comprise multiple vessels whichmay be arranged in series, parallel, or a combination thereof. Theseparation vessels may be of any shape and configuration to facilitatethe separation, collection, and removal of the two phases. In a furtherembodiment, contaminant removal zone 100 may include a single vesselwherein lean ionic liquid stream 4, Brønsted acid stream 5, andhydrocarbon feed stream 2 are mixed, then remain in the vessel to settleinto the hydrocarbon effluent and rich ionic liquid phases.

In an embodiment, the process comprises at least two contaminant removalsteps. For example, the hydrocarbon effluent from one contaminantremoval step may be passed directly as the hydrocarbon feed to a secondcontaminant removal step. In another embodiment, the hydrocarboneffluent from one contaminant removal step may be treated or processedbefore being introduced as the hydrocarbon feed to the secondcontaminant removal step. There is no requirement that each contaminantremoval zone comprises the same type of equipment. Different equipmentand conditions may be used in different contaminant removal zones.

The contaminant removal step may be conducted under contaminant removalconditions including temperatures and pressures sufficient to keep thehydrocarbon-immiscible ionic liquid and hydrocarbon feeds and effluentsas liquids. For example, the contaminant removal step temperature mayrange between about 10° C. and less than the decomposition temperatureof the ionic liquid, and the pressure may range between aboutatmospheric pressure and about 3 MPa(g). When the hydrocarbon-immiscibleionic liquid comprises more than one ionic liquid component, thedecomposition temperature of the ionic liquid is the lowest temperatureat which any of the ionic liquid components decompose. The contaminantremoval step may be conducted at a uniform temperature and pressure, orthe contacting and separating steps of the contaminant removal step maybe operated at different temperatures and/or pressures. In anembodiment, the contacting step is conducted at a first temperature, andthe separating step is conducted at a temperature at least 5° C. lowerthan the first temperature. In a non-limiting example, the firsttemperature is about 80° C. Such temperature differences may facilitateseparation of the hydrocarbon and ionic liquid phases.

The above and other contaminant removal step conditions such as thecontacting or mixing time, the separation or settling time, and theratio of hydrocarbon feed to hydrocarbon-immiscible ionic liquid (leanionic liquid) may vary greatly based, for example, on the specific ionicliquid or liquids employed, the Brønsted acid used, the nature of thehydrocarbon feed (straight run or previously processed), the contaminantcontent of the hydrocarbon feed, the degree of contaminant removalrequired, the number of contaminant removal steps employed, and thespecific equipment used. In general, it is expected that contacting timemay range from less than one minute to about two hours; settling timemay range from about one minute to about eight hours.

The weight ratio of hydrocarbon feed to lean ionic liquid introduced tothe contaminant removal step may range from about 1:10,000 to about10,000:1, or about 1:1,000 to about 1,000:1, or about 1:100 to about100:1, or about 1:20 to about 20:1, or about 1:10 to about 10:1. In anembodiment, the weight of hydrocarbon feed is greater than the weight ofionic liquid introduced to the contaminant removal step.

The degree of phase separation between the hydrocarbon and ionic liquidphases is another factor to consider as it affects recovery of the ionicliquid and hydrocarbon. The degree of contaminant removed and therecovery of the hydrocarbon and ionic liquid may be affected differentlyby the nature of the hydrocarbon feed, the variations in the specificionic liquid or liquids, the Brønsted acid, the equipment, and thecontaminant removal conditions such as those discussed above.

The amount of water present in the hydrocarbon/hydrocarbon-immiscibleionic liquid mixture during the contaminant removal step may also affectthe amount of contaminant removed and/or the degree of phase separation,i.e., recovery of the hydrocarbon and ionic liquid. In an embodiment,the hydrocarbon/hydrocarbon-immiscible ionic liquid mixture has a watercontent of less than about 10% relative to the weight of the ionicliquid, or less than about 5% relative to the weight of the ionicliquid, or less than about 2% relative to the weight of the ionicliquid. In a further embodiment, the hydrocarbon/hydrocarbon-immiscibleionic liquid mixture is water free, i.e., the mixture does not containwater.

Unless otherwise stated, the exact connection point of various inlet andeffluent streams within the zones is not essential to the invention. Forexample, it is well known in the art that a stream to a distillationzone may be sent directly to the column, or the stream may first be sentto other equipment within the zone such as heat exchangers, to adjusttemperature, and/or pumps to adjust the pressure. Likewise, streamsentering and leaving contaminant removal, washing, and regenerationzones may pass through ancillary equipment such as heat exchanges withinthe zones. Streams, including recycle streams, introduced to washing orextraction zones may be introduced individually or combined prior to orwithin such zones.

The invention encompasses a variety of flow scheme embodiments includingoptional destinations of streams, splitting streams to send the samecomposition, i.e. aliquot portions, to more than one destination, andrecycling various streams within the process. Examples include: variousstreams comprising ionic liquid and water may be dried and/or passed toother zones to provide all or a portion of the water and/or ionic liquidrequired by the destination zone. The various process steps may beoperated continuously and/or intermittently as needed for a givenembodiment e.g. based on the quantities and properties of the streams tobe processed in such steps. As discussed above the invention encompassesmultiple contaminant removal steps, which may be performed in parallel,sequentially, or a combination thereof. Multiple contaminant removalsteps may be performed within the same contaminant removal zone and/ormultiple contaminant removal zones may be employed with or withoutintervening washing, regeneration and/or drying zones.

By the term “about,” we mean within 10% of the value, or within 5%, orwithin 1%.

EXAMPLES

A digitally controlled Optichem hot plate magnetic stirrer with 17individual sample wells was used to screen ionic liquids fordecontamination properties. Each well could be fitted with a 6 dram (20cc) glass vial. The experiments were conducted in the vials with a ¾inch (1.9 cm) cross shaped magnetic stir bars for mixing. For thepurposes of the screening study, typically 1 gram of ionic liquid wascombined in a vial with 10 grams of feed, heated to appropriatetemperature and mixed at 500 rpm for 30 minutes. After 30 minutes, themixing was stopped, and the samples were held static at temperature. Insuccessful experiments, separation occurred, and the extracted feed wassuctioned off with a glass pipette. In some experiments, acid was addedto the ionic liquid, and in other experiments acid was used withoutionic liquid.

FCC naphtha, with the properties described in Table 1, was thehydrocarbon feed used in examples 1, 2 and 3. The boiling point range ofthe FCC naphtha was determined by ASTM method D2887, and the nitrogen,sulfur, water, density, and research octane number analyses wereperformed using ASTM methods D4629, D2622, D1364, D4052, and D2699Mrespectively.

TABLE 1 FCC Naphtha Nitrogen, ppm 115 Sulfur, ppm 2777 Water, ppm 109Research octane number 93 Density, g/cc 0.773 Boiling Range ° C. Initialboiling point at 0.5 wt % 30 Boiling point at 25.0 wt % 85 Boiling pointat 50.0 wt % 123 Boiling point at 75.0 wt % 162 Boiling point at 95.0 wt% 201 Final boiling point at 99.5 wt % 241

Example 1

FCC naphtha was weighed into 4 tared glass vials. In the first vial,triisobutylmethylphosphonium tosylate ionic liquid (IL) was added at aratio of 0.1 IL:naphtha. Triisobutylmethylphosphonium tosylate mixedwith H₂SO₄ was added to the IL in the second vial, the IL:naphtha ratiowas 0.1, and the acid:naphtha ratio was 0.03. The other 2 vialscontained naphtha plus H₂SO₄ at acid:naphtha ratios of 0.25 and 0.5. Thevials were placed in the wells of the Optichem stir plate and stirred atroom temperature for 30 minutes at 500 rpm. After 30 minutes, thestirring was stopped, and the mixtures were allowed to settle for 30minutes. A pipette was used to draw off the extracted naphtha from theextraction media. The naphtha phase was weighed and analyzed fornitrogen and sulfur. The extract yield was calculated based on thedifferences in weight. The % denitrogenation and extract yields forthese experiments are shown in Table 2.

TABLE 2 Extract mixing settling de-N, Yield, FCC Naphtha H2SO4/feedIL/Feed temp, ° C. time time wt % wt % triisobutylmethylphosphoniumtosylate 0 0.1 RT 30 30 81.74 2.2 triisobutylmethylphosphonium tosylate0.03 0.1 RT 30 30 82.61 3 triisobutylmethylphosphonium tosylate 0.05 0.1RT 30 30 90.43 ~1 5% H2SO4 0.25 0 RT 30 30 73.04 NA 10% H2SO4 0.5 0 RT30 30 76.52 NA

Example 2

FCC naphtha was weighed into 5 tared glass vials. In the first vialtributylethylphosphonium diethylphosphate ionic liquid (IL) was added ata ratio of 0.1 IL:naphtha. Tributylethylphosphonium diethylphosphatemixed with H₃PO₄ was added to the second and third vials. The ratio ofIL:naphtha was 0.1, and the ratios of acid:naphtha 0.03 and 0.05. Theother 2 vials contained naphtha plus H₃PO₄ at acid:naphtha ratios of0.25 and 0.5. The vials were placed in the wells of the Optichem stirplate and stirred at room temperature for 30 minutes at 500 rpm.

After 30 minutes, the stirring was stopped, and the mixtures wereallowed to settle for 30 minutes. A pipette was used to draw off theextracted naphtha from the extraction media. The naphtha phase wasweighed and analyzed for nitrogen and sulfur. The extract yield wascalculated based on the differences in weight. The % denitrogenation, %desulfurization and extract yields for these experiments are shown inTable 3.

TABLE 3 mixing settling de-N, de-S, Extract FCC Naphtha H3PO4/feedIL/Feed temp, ° C. time time wt % wt % Yield tributylethylphosphonium 00.1 RT 30 30 80.87 4.72 6 diethylphosphate tributylethylphosphonium 0.030.1 RT 30 30 76.52 4.25 3.9 diethylphosphate tributylethylphosphonium0.05 0.1 RT 30 30 80.87 1.98 1.8 diethylphosphate 5% H3PO4 0.25 0 RT 3030 75.65 0.18 NA 10% H3PO4 0.5 0 RT 30 30 74.78 1.98 NA

Example 3

FCC naphtha was weighed into 4 tared glass vials.Triisobutylmethylphosphonium tosylate ionic liquid (IL) was added at anIL:naphtha ratio of 0.1. P-toluene sulfonic acid was mixed in with theIL at different acid:naphtha ratios. The vials were placed in the wellsof the Optichem stir plate and stirred at room temperature for 30minutes at 500 rpm. After 30 minutes, the stirring was stopped, and themixtures were allowed to settle for 30 minutes. A pipette was used todraw off the extracted naphtha from the extraction media. The naphthaphase was weighed and analyzed for nitrogen and sulfur. The extractyield was calculated based on the differences in weight. The %denitrogenation, % desulfurization and extract yields for theseexperiments are shown in Table 4.

TABLE 4 P- toluenesulfonic mixing settling de-N, de-S, Extract FCCNaphtha acid/feed IL/Feed temp, ° C. time time wt % wt % Yieldtriisobutylmethylphosphonium tosylate 0 0.1 RT 30 30 83.48 4.86 4triisobutylmethylphosphonium tosylate 0.03 0.1 RT 30 30 83.48 4.86 4triisobutylmethylphosphonium tosylate 0.05 0.1 RT 30 30 84.35 5.33 4triisobutylmethylphosphonium tosylate 0.1 0.1 RT 30 30 84.35 2.92 3

Example 4

Light cycle oil (LCO) with the properties described in Table 5, was usedin Example 4. The boiling point range of the LCO was determined by ASTMmethod D2887, and the nitrogen, sulfur, water, density, and researchcetane number analyses were performed using ASTM methods D4629, D2622,D1364, D4052, and D613 respectively.

TABLE 5 LCO nitrogen, ppm 1500 density 0.9655 Sulfur, ppm 9442 cetane18.41 water, ppm 228 % C5-203° C. 4.84 % 204-343° C. 82.46 % 344-524° C.12.70 % 524+° C. 0.00

Light cycle oil (LCO) was weighed into 5 tared glass vials. In the firstvial, triisobutylmethylphosphonium tosylate ionic liquid (IL) was addedat a ratio of 0.1 IL:LCO. Triisobutylmethylphosphonium tosylate mixedwith H₂SO₄ was added to the second and third vials. The ratio of IL:LCOwas 0.1, and the ratios of acid:LCO were 0.03 and 0.05. The other 2vials contained LCO plus H₂SO₄ at acid:LCO ratios of 0.25 and 0.5. Thevials were placed in the wells of the Optichem stir plate and stirred atroom temperature for 30 minutes at 500 rpm. After 30 minutes, thestirring was stopped, and the mixtures were allowed to settle for 30minutes. A pipette was used to draw off the extracted LCO from theextraction media. The LCO phase was weighed and analyzed for nitrogen.The extract yield was calculated based on the differences in weight. The% denitrogenation and extract yields for these experiments are shown inTable 6.

TABLE 6 Extract mixing settling de-N, Yield, Light Cycle Oil H2SO4/feedIL/Feed temp, ° C. time time wt % wt % triisobutylmethylphosphonium 00.1 RT 30 30 85.76 10 tosylate triisobutylmethylphosphonium 0.03 0.1 RT30 30 68.61 7 tosylate triisobutylmethylphosphonium 0.05 0.1 RT 30 3064.49 6 tosylate H2SO4 0.25 0 RT 30 30 44.77 6 H2SO4 0.5 0 RT 30 3032.25 2

Example 5

Vacuum gas oil (VGO) with properties described in Table 7, was used inExample 5. The boiling point range of the VGO was determined by ASTMmethod D2887, nitrogen, sulfur, and density analyses were performedusing ASTM methods D4629, D2622, and D4052 respectively.

TABLE 7 Feed VGO Density (g/mL) 0.9271 Sulfur, wt % 2.99 Nitrogen,wt-ppm 1400 Boiling Range, ° C. Initial Boiling point at 0.5 wt % 291.8Boiling point at 25 wt % 399.4 Boiling point at 50 wt % 437.8 Boilingpoint at 75 wt % 478.8 Boiling point at 95 wt % 532.6 Final boilingpoint at 99.5 wt % 659

Vacuum gas oil (VGO) was weighed into a beaker. Triisobutylmethylphosphonium tosylate ionic liquid (IL) was added at a ratio of 0.1IL:VGO. The mixture was stirred for 30 minutes at 80° C. and thensettled for 30 minutes at 80° C. The extracted VGO floated to the top ofthe beaker and was suctioned away with a pipette. The remaining ionicliquid phase containing extract from the VGO was diluted with water at a1:1 weight ratio. The water addition freed the extract from the ionicliquid and the extract was suctioned away using a pipette. The water wasevaporated from the ionic liquid via rotary flash evaporation. P-toluenesulfonic acid (PTSA) was added to the regenerated ionic liquid at aratio of PTSA:IL of 0.03. The acid IL mixture was combined with freshVGO at a ratio of IL:VGO of 0.1. The mixture was stirred for 30 minutesat 80° C. and then settled for 30 minutes at 80° C. The extracted VGOfloated to the top of the beaker and was suctioned away with a pipette.The Brønsted acid and the ionic liquid phase containing the extract fromthe VGO was diluted with water at a 1:1 weight ratio. The water additionfreed the extract from the Brønsted acid and the ionic liquid and theextract was suctioned away using a pipette. The water and the Brønstedacid were evaporated from the ionic liquid via rotary flash evaporation.Additional PTSA was added to the regenerated IL to make-up for the lossto evaporation. The IL with added PTSA was then used to extract freshVGO. This procedure was repeated four additional times. The %denitrogenation and the extract yields for these experiments are shownin Table 8.

TABLE 8 Extract mixing settling de-N, Yield, VGO Cycle # PTSA/IL IL/Feedtemp, ° C. time time wt % wt % triisobutylmethylphosphonium 1 0.00 0.180 30 30 38.79 2.90 tosylate triisobutylmethylphosphonium 2 0.03 0.1 8030 30 35.35 2.90 tosylate triisobutylmethylphosphonium 3 0.03 0.1 80 3030 39.21 3.27 tosylate triisobutylmethylphosphonium 4 0.03 0.1 80 30 3039.21 3.05 tosylate triisobutylmethylphosphonium 5 0.03 0.1 80 30 3038.37 3.19 tosylate triisobutylmethylphosphonium 6 0.03 0.1 80 30 3044.27 3.23 tosylate

While at least one exemplary embodiment has been presented in theforegoing detailed description of the invention, it should beappreciated that a vast number of variations exist. It should also beappreciated that the exemplary embodiment or exemplary embodiments areonly examples, and are not intended to limit the scope, applicability,or configuration of the invention in any way. Rather, the foregoingdetailed description will provide those skilled in the art with aconvenient road map for implementing an exemplary embodiment of theinvention. It being understood that various changes may be made in thefunction and arrangement of elements described in an exemplaryembodiment without departing from the scope of the invention as setforth in the appended claims.

What is claimed is:
 1. A process for removing a contaminant comprisingat least one of sulfur and nitrogen from a hydrocarbon streamcomprising: contacting the hydrocarbon stream comprising the contaminantwith a Brønsted acid, or a hydrocarbon-immiscible ionic liquid and aBrønsted acid under contacting conditions so that the Brønsted acid, orthe hydrocarbon-immiscible ionic liquid and the Brønsted acid are in aliquid state to produce a mixture comprising the hydrocarbon and theBrønsted acid comprising at least a portion of the removed contaminantor a hydrocarbon-immiscible ionic liquid comprising at least a portionof the removed contaminant; and separating the mixture to produce ahydrocarbon effluent having a reduced level of the contaminant and aBrønsted acid effluent comprising the Brønsted acid comprising at leastthe portion of the removed contaminant or a hydrocarbon-immiscible ionicliquid effluent comprising the hydrocarbon-immiscible ionic liquidcomprising at least the portion of the removed contaminant.
 2. Theprocess of claim 1 wherein the hydrocarbon-immiscible ionic liquidcomprises at least one of nitrogen containing ionic liquids andphosphorus containing ionic liquids.
 3. The process of claim 1 whereinthe Brønsted acid comprises sulfonic acid, derivatives of sulfonic acid,sulfuric acid, phosphoric acid, derivatives of phosphoric acid,phosphonic acid, derivatives of phosphonic acid, hydrochloric acid,hydrobromic acid, nitric acid, sulfurous acid, carboxylic acids havingfrom 1 to 8 carbons, and combinations thereof.
 4. The process of claim 1wherein a ratio of the Brønsted acid to the hydrocarbon-immiscible ionicliquid is in a range of about to about 0.01:1 to about 0.5:1.
 5. Theprocess of claim 1 wherein the hydrocarbon stream has a boiling point ina range of about 30° C. to about 525° C.
 6. The process of claim 1wherein the contacting step is conducted at a temperature in a range ofabout 20° C. to about 150° C., and a pressure in a range of about 100kPa (g) to about 3 MPa(g).
 7. The process of claim 1 further comprisingpassing at least a portion of the hydrocarbon effluent to a hydrocarbonconversion process.
 8. The process of claim 1 further comprising:regenerating the hydrocarbon-immiscible ionic liquid effluent; andrecycling the regenerated hydrocarbon-immiscible based ionic liquideffluent to the contacting step.
 9. The process of claim 1 wherein aratio of the hydrocarbon to the hydrocarbon-immiscible ionic liquid isin a range of about 1:1,000 to about 1,000:1.
 10. The process of claim 1further comprising contacting the hydrocarbon-immiscible ionic liquideffluent with a regeneration solvent to form an extract streamcomprising the contaminant and a stream of regeneratedhydrocarbon-immiscible ionic liquid.
 11. The process of claim 10 whereinthe regeneration solvent comprises water, naphtha, gasoline, diesel,light cycle oil, light coker gas oil, alcohols, aldehydes, ketones,ether, and combinations thereof.
 12. The process of claim 10 furthercomprising separating the stream of regenerated hydrocarbon-immiscibleionic liquid from the regeneration solvent.
 13. The process of claim 12further comprising recycling the stream of regeneratedhydrocarbon-immiscible ionic liquid to the contacting step.
 14. Theprocess of claim 1 wherein the ionic liquid comprises an imidazoliumionic liquid, an ammonium ionic liquid, a pyridinium ionic liquid, aphosphonium ionic liquid, a lactamium ionic liquid, a pyrrolidiniumionic liquid, or combinations thereof.
 15. The process of claim 1wherein the hydrocarbon effluent contains less than 25 ppmhydrocarbon-immiscible ionic liquid.
 16. A process for removing acontaminant comprising at least one of sulfur and nitrogen from ahydrocarbon stream comprising: contacting the hydrocarbon streamcomprising the contaminant with a hydrocarbon-immiscible ionic liquidand a Brønsted acid under contacting conditions so that thehydrocarbon-immiscible ionic liquid and the Brønsted acid are in aliquid state to produce a mixture comprising the hydrocarbon and ahydrocarbon-immiscible ionic liquid comprising at least a portion of theremoved contaminant, wherein the hydrocarbon stream has a boiling pointin a range of about 30° C. to about 525° C., wherein thehydrocarbon-immiscible ionic liquid comprises an imidazolium ionicliquid, an ammonium ionic liquid, a pyridinium ionic liquid, aphosphonium ionic liquid, a lactamium ionic liquid, a pyrrolidiniumionic liquid, or combinations thereof, and wherein the Brønsted acidcomprises sulfonic acid, derivatives of sulfonic acid, sulfuric acid,phosphoric acid, derivatives of phosphoric acid, phosphonic acids,derivatives of phosphonic acid, hydrochloric acid, hydrobromic acid,nitric acid, sulfurous acid, carboxylic acids having from 1 to 8carbons, and combinations thereof, and wherein a ratio of the Brønstedacid to the hydrocarbon-immiscible ionic liquid is in a range of aboutto about 0.01:1 to about 0.5:1; and separating the mixture to produce ahydrocarbon effluent having a reduced level of the contaminant and ahydrocarbon-immiscible ionic liquid effluent comprising thehydrocarbon-immiscible ionic liquid comprising at least the portion ofthe removed contaminant, wherein the hydrocarbon effluent contains lessthan 25 ppm hydrocarbon-immiscible ionic liquid.
 17. The process ofclaim 16 wherein the contacting step is conducted at a temperature in arange of about 20° C. to about 150° C.
 18. The process of claim 18further comprising: regenerating the hydrocarbon-immiscible ionic liquideffluent; and recycling the regenerated hydrocarbon-immiscible basedionic liquid effluent to the contacting step.
 19. The process of claim 1wherein the hydrocarbon-immiscible ionic liquid effluent is regeneratedby contacting the hydrocarbon-immiscible ionic liquid effluent with aregeneration solvent to form an extract stream comprising thecontaminant and a stream of regenerated hydrocarbon-immiscible ionicliquid, and further comprising: separating the stream of regeneratedhydrocarbon-immiscible ionic liquid from the regeneration solvent. 20.The process of claim 19 wherein the regeneration solvent compriseswater, naphtha, gasoline, diesel, light cycle oil, light coker gas oil,alcohols, aldehydes, ketones, ether, and combinations thereof.